1. Field of the Invention
The present invention relates to well killing systems. More particularly, the present invention relates to techniques for injecting fluids into a relief well. Additionally, the present invention relates to diverter spools in association with a blowout preventer on a relief well.
2. Description of Related Art Including Information Disclosed Under 37 CFR 1.97 And 37 CFR 1.98.
Several methods can be considered to control offshore blowouts, but they can all be classified as surface interventions or relief well methods, depending on the intervention approach. Surface intervention aims to control the blowout by direct access to the wellhead or fluid exit point of the wild well. Relief wells are used to gain control of blowouts in situations where direct surface intervention is impossible or impractical. Instead, relief well methods include killing the uncontrolled well downhole from a surface location at a safe distance away from the wild well. Blowout and kill simulation studies have shown that some wells could require more than one relief well for a dynamic kill operation.
In the aftermath of the Macondo blowout in the Gulf of Mexico in 2010, the development of surface intervention methods and subsea capping systems received a great deal of focus, but a operator will recognize that drilling a relief well followed by a dynamic kill operation will, in many cases, be the safest and most likely successful well intervention. Furthermore, in some blowout scenarios, it will be the only way to regain control. It is therefore important that the operator can demonstrate the feasibility of the relief well operation on a particular well and field.
Relief wells have been drilled regularly as a last-resort well-intervention method when other surface kill efforts have failed. In the early 20th century, relief wells were spudded in close proximity to a blowout and drilled vertically to the reservoir. Subsequently, the formation must be produced at a high rate to relieve pressure, which is where the “relief well” name originates. A milestone for directional relief wells occurred in 1933 when a blowout was killed for the first time by directly intersecting the flowing wellbore. The first application of magnetic ranging to achieve a downhole well intersection was performed in 1970. This ranging technique was further refined in the 1980s, which is now the basis of modern relief-well planning.
The dynamic kill technique for relief well kill was first defined by Mobil in 1981. In 1989, a blowout occurred in the Norwegian North NCS, where the dynamic kill operation was planned using the first dynamic kill simulator named OLGA-WELL-KILL. Since then, OLGA-WELL-KILL has evolved to become the industry's leading dynamic kill simulator and has been used successfully to plan an extensive number of blowout interventions.
The dynamic kill technique has been established as the preferred method for killing a blowout after intersecting with a relief well. The dynamic kill uses the increased hydrostatic head of a mixture of gas, oil, and mud in the blowing well together with the frictional pressure drop to increase the bottomhole pressure and consequently stop the flow from the reservoir. For very prolific/hard-to-kill blowouts, the pump rate necessary to be delivered at the intersection point can be beyond what can normally be pumped from a single relief well rig. This will trigger options to optimize the capacity of the relief well for the planning of two or more relief wells.
Multiple relief wells may be planned even when the kill measurements are within the limitations of a single drilling rig. In other words, a prolific blowout results in a massive discharge of oil so as to justify a secondary relief well as a back-up in case the primary well does not meet the target. This has been the case for many historical relief-well projects during the 2010 Macondo blowout, where two relief wells were drilled, but only one relief well actually intersected the target well. In fact, the only known incident were two relief wells simultaneously intersected a blowing wellbore was used for a dynamic kill is the 1995 Le-Isba onshore blowout in Syria. There is no actual experience of intersecting and coordinating a dynamic kill in offshore environment with multiple relief wells.
A kill operation with two relief wells is recognized as being a challenging operation. Two or more drilling rigs for the specific operation must be mobilized. Each of the drilling rigs drill a relief well from an approved surface location. Furthermore, both relief wells will have to simultaneously locate and intersect the blowing wellbore. The blowing well must be killed through a simultaneous coordinated kill operation. Complex operations are, in general, more time-consuming. As a result, this will increase the total volume of oil and gas released to the environment.
As a result of the limited experience with potential challenges, the NORSOK D-010 well integrity standard states that, for offshore wells, the well design should enable killing a blowout with one relief well. If two relief wells are required, the feasibility of such an operation must be documented. An offshore well design that requires more than two relief wells is not acceptable. Similarly, other governmental agencies will not grant approval for a permit to kill an exploration well if a worst-credible blowout may require two or more relief wells for the kill operation.
If the kill requirements are excessive and a drilling permit is not granted, the planned well design can, in some cases, be revised to lower the pumping requirements within the capacity of a single relief well. Some examples include setting the last casing string deeper to allow a deeper relief-well intersect, using a smaller diameter casing to increase friction during the dynamic kill, setting additional casing strings to isolate sands, or drilling a smaller hole size to lower the flow potential of potential flowing sands. In these cases, the planned well design is driven by dynamic kill requirements. An example of this is the Chevron Wheatstone project in which additional casing strings were set to allow a deeper relief well intersect and increase friction pressure in the blowout well during a dynamic kill.
Setting additional casing strings may come at a high cost since it requires great time, introduces additional risks, and could affect production rates. In other words, well is designed for smaller casing and, as result, smaller production tubing will flow at a lower rate per well than with larger tubing sizes. This may have a significant impact on the overall field development cost increase in the number of wells required to produce at a given rate. The cost increase of a standard well design can be in on the order of $50 million per well higher than for a big-bore well.
For a blowout where a relief well intervention is the only option and the kill requirements are expected to be very demanding, alternatives to multiple relief wells can include the risk of reducing the required pumping rate, performing a staged kill with high-density kill mud followed by a later static mud, or using special or reactive kill fluids. These techniques have been used on actual project with some success, but they may introduce additional risk and complexity. For blowout contingency planning, it is a proper business practice to be conservative and to plan for a standard dynamic kill with a uniform mud and with enough pump redundancy that the kill rate can be maintained if one pump fails. Thus, increasing the pumping capacity of a single relief well will often be the best alternative than relief to multiple relief wells.
When initiating a dynamic kill for a floating rig with the wellhead at the seabed, the relief well will be shut in at the blowout preventer using the pipe rams and kill fluid will be pumped down the choke-and-kill lines to the blowout preventer at the wellhead. Depending on the water depth and the choke-and-kill line size, the flow capacity and hence the pressure drop in the choke-and-kill lines could have a significant impact on the total flow rate that can be pumped down the relief well. For a deepwater relief well pumping operation, it is therefore critical to use a drilling rig with large diameter choke-and-kill lines.
To monitor the downhole pressure during the dynamic kill operation, the drill pipe must be in the wellbore. The size and length of the bottomhole assembly and the drill pipe could influence the total pressure drop in the wellbore. If required, the drill pipe and the bottom hole assembly can be swapped just prior to drilling the last few meters before reaching the intersection. To further enhance the flow capacity in the relief well, the casing design must be evaluated. A typical relief well design would include a 9⅝ inch casing set prior to intersection with a 7 inch liner as a contingency to protect the open hole prior to the intersection point. If the 9⅝ inch casing is substituted with a liner, the flow capacity in the relief well may also increase significantly.
Pumping down both the annulus and the drill pipe simultaneously during the kill will increase the flow capacity and reduce the total pressure drop even further. This requires a pressure sensor in the bottom hole assembly to measure the dynamic pressure of well pumping to avoid fracturing operations during the kill and to know when to reduce the kill rate after the flowing bottom hole pressure exceeds the pore pressure. Performing the kill operation without downhole-pressure control is not recommended.
The methods mentioned above for increasing flow capacity may lower the required pumping pressure and hydraulic horsepower for the kill operation. However, if the required kill rate is still beyond the rig capacity, then additional pumping units must be added. Offshore drilling rigs suitable for relief well operations are required with a number of mud pumps and a cementing unit. However, if additional pump units are needed, then they must be lined up to the rigs' existing floor-space and high-pressure manifold system, which might require modification and redesign of the piping system. Additional pumps on deck also add weight and use up deck space. On many rigs, this can be a limiting factor.
To increase the pumping capacity of the relief well, a dedicated kill plant located on an independent dynamically-position support vessel will likely be preferred. The support vessel could be a drilling or workover rig, a stimulation vessel, or a floating barge with a high-pressure kill plant. To supply mud to the high-pressure pumping vessel, a large dynamically-positioned platform supply vessel with centrifugal pumps and low-pressure hoses positioned alongside the pumping vessel can be used.
To increase the pump capacity for the relief well, the dedicated kill plant on the support vessel will need to be linked together with the mud system of the relief well rig. There are three points-of-connection to be considered. These are the surface interface on the rig deck, the subsea interface with the rig equipment, and the subsea interface with a dedicated manifold located between the wellhead and the blowout preventer. The surface interface on the rig deck is a surface interface and the rig deck is a surface connection between two vessels. This is the industry operating practice to increase fluid storage and pumping capacity. Vessels are connected by high-pressure flex lines to a temporary high-pressure manifold constructed on the rig floor, which is then tied into the choke-and-kill lines. In addition to limitations of the size of the choke-and-kill lines, the flex lines need to be short enough to limit frictional losses, but long enough that wind, waves, and current would not cause the vessels to collide. The vessels would likely need to disconnect in seas of approximately four meters or greater.
In relation to the subsea interface with rig equipment, for a deep water relief well with a subsea wellhead, the kill fluid is pumped down the choke-and-kill lines to the blowout preventer and subsequently to the relief-well annulus between the wellbore in the drill pipe. The choke-and-kill lines are an integral part of the riser system, and they are connected to the blowout preventer/lower marine riser package mounted at the top of the wellhead. No additional inlets are available for pumping unless the system is redesigned and modified. One concept is to install a temporary manifold between the blowout preventer and the lower marine riser package. However, this would likely cause loss of the blowout preventer function. As such, it is considered impractical. A second concept is to cut the choke-and-kill lines on one of the riser elements and retrofit a Y-branch joint the can be used as a tie-in point for the flex lines from the support vessels. This would need to require the entire riser to be pulled to the surface (which would be time-consuming) or a second rig with a different riser system would need to be mobilized. Furthermore, with a Y-branch welded to the side of a riser element, the assembly might not fit through the rig rotary due to its external dimensions. Instead, the riser element would be deployed to the side and subsequently moved underneath the rig to be connected with the riser. A subsea interface with existing rig equipment would require modifications to suite-specific riser types and each individual blowout preventer/lower marine riser package interface. In the event of a blowout disaster, a solution that calls for major on-the-fly modifications to tailor-made equipment would add significant risks to the operation or would likely be disapproved by rig contractors, regulatory agents, and other stakeholders.
In relation to the subsea interface with a dedicated manifold located between the wellhead and the blowout preventer, it is believed that a dedicated manifold with flow line connector is located between the wellhead in the blowout preventer would be the preferred and advantageous solution. As such, the present invention was developed so as to achieve such a configuration.
In the past, various patents have issued relating to techniques for controlling downhole pressures and for containing fluids. For example, U.S. Pat. No. 9,057,243, issued on Jun. 16, 2015, to Hendell et al., discloses an enhanced hydrocarbon well blowout protection system. The protection at a hydrocarbon well is enhanced by placing a blowout preventer over a wellhead. An adapter is connected to the blowout preventer. The adapter includes a valve that, when turned off, prevents non-production flow from the blowout preventer to a riser pipe.
U.S. Pat. No. 4,378,849, issued on Apr. 5, 1983, to J. A. Wilkes, teaches a blowout preventer having an mechanically-operated relief valve. The blowout preventer has a mechanical linkage to a valve connected to a pressure relief line in the casing beneath the blowout preventer whereby the valve on the pressure relief line is opened when the blowout preventer is actuated. The blowout preventer includes an upright tubular body having an annular packing therein which can be constructed about a drill pipe or other pipe in the well, a head connected to the top of the upright tubular body for containing the annular packing in the body, a piston slidably received in the body and adapted to selectively constrict the packing about the well pipe, a casing pipe connected to the lower end of the body for containing the well pipe, a pressure relief line connected to the casing having a valve therein, and a rod connected to the piston and the valve to open the valve when the piston slides within the tubular body to constrict the packing about the well pipe.
U.S. Pat. No. 3,457,991, issued on Jul. 29, 1969 to P. S. Sizer, discloses a well control flow assembly which includes a plurality of blowout preventers and an automatic subsurface safety valve positioned in the blowout preventers. The valve is biased to a closed position and is moved to an open position by pressure fluid which is controlled by means positioned at the surface of the well. One object of this invention is to provide a new and improved flow control assembly which is installable in the well during the drilling of the well. It is held in place in the well installation by blowout preventers used in the drilling of the well. It is provided with a valve located below the blowout preventers which may be controlled from the surface for controlling flow from the well.
U.S. Patent Application Publication No. 2012/0305262, published on Dec. 6, 2012, to Ballard et al., shows a subsea pressure relief device. This device serves to relieve pressure and a subsea component. The device includes a housing included including an inner cavity, and open end in fluid communication with the inner cavity, and a through bore extending from the inner cavity to an outer surface of the housing. The device has a connector coupled to the open end. The connector is configured to releasably engage a mating connector coupled to the subsea component. The device further includes a burst disc assembly mounted to the housing within the through bore. The burst disc assembly is configured to rupture at a predetermined differential pressure between the inner cavity in the environment outside the housing.
U.S. Patent Application Publication No. 2012/0001100, published on Jan. 5, 2012 to P. J. Hubbell, discloses a blowout preventer-backup safety system. The system serves to address the problem of having a failed blowout preventer. This provides an independent backup safety system when encountering an oil/gas well “kick” or blowout and is not reliable in any of the complex, multiple components of the blowout preventer. The system includes a double manifold, double bypass device which is a supplemental connection between the wellhead in the inlet of the blowout preventer that allows for relief for both temporary and/or extended time. Until repairs, replacements, or capping procedures are complete.
European Patent No. 0709545, published the Jan. 15, 2003 to S. Gleditsch, teaches a deep water slim hole drilling system. The system relates to an arrangement used for drilling oil or gas wells, especially deep water wells. This system provides instructions for how to utilize the riser pipe as part of the high-pressure system together with the drilling pipe. The arrangement comprises a surface blowout preventer which is connected to a high-pressure riser pipe which input, in turn, is connected to a well blowout preventer. A circulation/kill line communicates between the blowout preventers.
International Publication No. WO 2012174194 in the name of the present applicant discloses a diverter system for a subsea well which has a blowout preventer and a diverter affixed to an outlet of the blowout preventer. The blowout preventer has an interior passageway with an inlet at the bottom thereof and an outlet at the top thereof. The diverter has a flow passageway extending therethrough and in communication with the interior passageway of the blowout preventer. The diverter has a valve therein for changing a flow rate of a fluid flowing through the flow passageway. The diverter has at least one channel opening in valved relation to the flow passageway so as to allow fluid from the flow passageway to pass outwardly of the diverter. At least one flow line is in valved communication with the flow passageway so as to allow fluids or materials to be introduced into the flow passageway.
International Publication No. WO1986002696, published on May 9, 1986, to J. R. Roche, shows a marine riser well control method and apparatus. This method and apparatus serves to maintain safe pressure in the annulus of a deepwater marine riser by preventing the displacement of drilling mud with formation gas. By providing an improved flow diverting control device having an annular sealing device in the riser string below the riser telescopic joint, liquid well fluids under limited pressure can be maintained in the riser despite the impetus of formation gas below the mud column to displace the liquid. The provision of an annular shut-off below the telescopic joint eliminates the necessity to seal well fluid pressure at the telescopic joint packer during kick control circulating operations. The flow diverting control device includes an outlet which opens on the opening of the annular sealing device and which provides a flow path beneath the annular sealing device to a choke lined to facilitate bringing the well under control by circulating kill mud. If the blowout preventer stack is on the bottom, circulation can be directed down a riser kill line in introduced into the annudus above a closed ram. If the blowout preventer is open or if the stack is not on the bottom, circulation is directed down the drill pipe, up the riser annulus and through a choke manifold. By maintaining a mud column in the riser annulus, the hazard of collapsing the pipe by an external hydrostatic head near the lower end of a deepwater marine riser is avoided.
It is an object of the present invention to provide a relief well injection spool that enhances cost savings by eliminating casing strings on weld trip designs driven by dynamic-kill requirements.
It is another object of the present invention provide a relief well injection spool that moves the additional mud and pump storage challenges from the rig to remotely-located support vessels.
It is another object the present invention provide a relief well injection spool that allows the support vessels to wait to mobilize closer to the time of the relief-well intersection.
It is another object of the present invention to provide a relief well injection spool which allows the loading of the kill fluid to be performed at an onshore terminal while the relief well is being drilled.
It is another object of the present invention to provide a relief well injection spool that eliminates the necessity of installing pumps and storage tanks on the relief well rig.
It is another object of the present invention to provide a relief well injection spool that eliminates the use of boats or ships in close proximity to the relief well.
It is still another object of the present invention to provide a relief well injection spool that enhances the safety of personnel on the relief well rig and on the boats or ships during operation.
It is still further object the present invention to provide a relief well injection spool that is independent of the relief well rig and equipment.
It is another object of the present invention to provide a relief well injection spool that allows any rig to be chosen for the relief well operation.
It is still further object of the present invention to provide a relief well injection spool which can be mobilized in a minimal amount of time.
It is still a further object of the present invention to provide a relief well injection spool that enhances well design and oil spill contingency plans.
It is still a further object the present invention provide a relief well injection spool which allows a potential worst-case blowout scenario to be killed with a single relief well.
These and other objects and advantages of the present invention will become apparent from a reading of the attached specification and appended claims.